There is growing concern that emission of CO2 and other greenhouse gases to the atmosphere is resulting in climate change and other as yet unknown consequences. Because existing fossil fuel fired power plants are among the largest sources of CO2 emissions, capture of the CO2 in flue gases from these plants has been identified as an important means for reducing atmospheric CO2 emissions. To that end, oxygen firing is a promising boiler technology being developed to capture CO2 from flue gases of both existing and new power plants.
In an oxygen fired power plant, a fossil fuel (such as coal, for example) is burned in a combustion process in a furnace of the power plant in a similar manner as in a conventional, e.g., air fired, power plant. In the oxygen fired power plant, however, oxygen and recirculated flue gas are used instead of air as an oxidizer in the combustion process. The recirculated flue gas contains primarily CO2 gas; as a result, the furnace generates a CO2 rich flue gas stream. The CO2 rich flue gas is processed by a gas processing system, which captures the CO2 from the flue gas prior to exhausting the flue gas to the atmosphere via a stack. In a typical oxygen-fired power plant, CO2 levels in the flue gas leaving the furnace are reduced by more than 90% (percent-by-volume) before reaching the stack.
In addition to capturing CO2 from the flue gas, the gas processing system of an oxygen-fired boiler purifies the CO2 by partially removing impurities inherent to the flue gas, primarily water (H2O), oxygen gas (O2), and nitrogen gas (N2). The H2O in the flue gas is unavoidable, since it comes from H2O in the coal itself, as well as combustion of hydrogen, which is also part of the coal. The H2O is relatively easy to remove, however, using a staged cooling/water vapor condensation process and/or a desiccant type dryer system.
Some of the O2 and N2 in the flue gas are unavoidable, as well. For example, some excess O2 is normally required to ensure complete combustion of the coal, and therefore some of the residual O2 will be present in the flue gas. In addition, some N2 is typically contained in the coal itself Further, residual N2 is often present with the O2 supplied as the oxidizer, particularly in power plants which use a cryogenic type air separation unit to generate the O2 to be used as the oxidizer.
Air leakage into the boiler also contributes to flue gas impurities such as O2 and N2. Air typically leaks into the boiler via openings such as around sootblowers and wall-blowers where they penetrate the boiler, around boiler access doors, from air cooling systems for scanner and igniters, through coal pulverizers, and via boiler tube penetrations in penthouses and backpasses, for example. Air leakage into flue gas can be significant. For example, air leakage into a typical pulverized coal boiler may be as high as approximately 5% of the total combustion air, and older boilers may have even more air leakage.
As a result of the above-mentioned sources of impurities, O2 and N2 together, for example, typically make up of approximately 4 wt % (percent by weight) to 15 wt % of the flue gas in a typical oxygen fired boiler. These additional gases must be reduced by the gas processing system, and therefore result in larger, more costly equipment. In addition, the additional gases increase electrical power consumption for the CO2 capture process, since more fan and/or compressor power is required to capture a given amount of CO2.
The additional gases also affect the dew point of CO2, e.g., a critical temperature of CO2 for condensation and removal from the flue gas. More specifically, achievable CO2 recovery is a function of both temperature and pressure. Partial pressures associated with the additional gases increase a total pressure of the flue gas, thereby making condensation of the CO2 more difficult, or even impossible, without raising operating temperature and/or pressure of the gas processing system. For example, at a gas processing system temperature of −60° F., a CO2 recovery rate of 95% can be achieved from flue gas having approximately 4 wt % of additional gases at a pressure of approximately 300 psig. At the same temperature, however, the same CO2 recovery rate can only be achieved for flue gas having 15 wt % additional gases by raising pressure to approximately 1000 psig. Thus, for the same recovery rate, more expensive, larger and/or more robust equipment, e.g., equipment capable of handling the higher pressure, must be utilized in the gas processing system. At the same time, more power is required to operate the CO2 recovery system, such as to operate larger compressors capable of generating the higher pressure, for example.
Accordingly, it is desirable to develop an air infiltration abatement system which overcomes the problems described above.